mountain valley pipeline motion to intervene...2018/12/10 · mountain valley pipeline, llc docket...

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UNITED STATES OF AMERICA

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

In the Matter of

MOUNTAIN VALLEY PIPELINE, LLC Docket No. CP19-14-000

MOTION TO INTERVENE AND PROTEST OF APPALACHIAN MOUNTAIN

ADVOCATES, APPALACHIAN VOICES, CENTER FOR BIOLOGICAL

DIVERSITY, CHESAPEAKE CLIMATE ACTION NETWORK, HAW RIVER

ASSEMBLY, AND THE SIERRA CLUB

I. MOTION TO INTERVENE

Pursuant to 18 C.F.R. §§ 157.10, 385.211, and 385.214, the following parties

move to intervene and protest in the above-captioned proceedings and request an

evidentiary hearing on the application of Mountain Valley Pipeline, LLC (“Mountain

Valley”) for the Southgate Project (“the Project”):

Appalachian Mountain Advocates is a non-profit law and policy center focused

on protection of the environment and human communities in the Appalachian region,

with offices in Virginia and West Virginia. Appalachian Mountain Advocates works to

promote sensible energy policies that protect the environmental and economic well-being

of the citizens of the region in the short and long term. Appalachian Mountain Advocates

opposes any energy development that unreasonably impacts the region’s communities,

landscapes, and water resources and contributes to long-term reliance on climate-altering

fossil fuels.

Appalachian Voices is an award-winning, nonprofit organization working in

partnership with local people and communities to defend the natural heritage and

economic future of the Appalachian region. Our primary focus is to strengthen the

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citizens movement across Virginia, West Virginia, North Carolina, Tennessee and

Kentucky to shift the region away from harmful, polluting energy practices — like

mountaintop removal coal mining and natural gas fracking — to cleaner, more just and

sustainable energy sources.

Appalachian Voices has offices in Charlottesville and Norton, Va., Knoxville,

Tenn., and Asheville and Chapel Hill, N.C. and employs 29 passionate, professional

individuals including environmental policy experts, community organizers and water

quality specialists. Appalachian Voices has almost 1,000 dues-paying members, plus

another 25,000 supporters throughout the country who take action to help us achieve our

goals. The Project would pose unacceptable environmental damage and health risks to

our members and supporters along the 73-mile proposed route through Virginia and

North Carolina and would compound the harmful impacts that people in the Appalachian

region living near natural gas fracking sites already experience. Further, public and

private investment in this project would lock the country into decades more of

dependence on fossil fuels, diverting those investments away from cleaner, more

sustainable energy options for the region including efficiency and wind and solar

generation.

The Center for Biological Diversity (“Center”) is a national, nonprofit

conservation organization with over 1.6 million members and online activists dedicated

to the protection of endangered species, a safe climate, wild places, and a healthy

environment. Among our key priorities is preventing the construction of new, dirty fossil

fuel facilities as a means to guard against environmental degradation and encourage the

development of clean, renewable energy sources. The Center has offices in Asheville

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and Raleigh, North Carolina, as well as Norfolk, Virginia. We enjoy over 63,000 dues-

paying members, and over 1.5 million online activists nationwide.

The construction and operation of the MVP Southgate pipeline would harm the

interests of our members by facilitating the hydraulic fracturing and fossil fuel production

that degrades the climate, environmental health, and endangered species habitat that we

seek to defend. The pipeline’s route would threaten the environmental health of the

communities through which it would pass with hazardous spills. Furthermore, the

pipeline would threaten the aquatic habitat of the Atlantic pigtoe, an imperiled freshwater

mussel currently proposed for listing under the Endangered Species Act.

The Chesapeake Climate Action Network (“CCAN”) is the first grassroots,

nonprofit organization dedicated exclusively to fighting climate change and all of the

harms fossil-fuel infrastructure causes in Maryland, Virginia, and Washington, D.C. and

to securing policies that will put us on a path to climate stability. CCAN has offices in

Takoma Park, Md., Richmond, Va., and Norfolk, Va. One of the primary tools CCAN

uses to fight climate change and move toward a clean-energy future is building,

educating, and mobilizing a powerful grassroots movement to push for a societal switch

away from dirty fossil-fuel energy and toward clean energy. In support of its mission,

CCAN opposes projects that could contribute to climate change, harm the public, and

degrade the Chesapeake Bay.

CCAN has over 60,000 supporters in Maryland, Virginia, and Washington, D.C.

who have signed up to receive updates from CCAN, donated to CCAN, signed an online

petition, or attended a CCAN-sponsored event. Of our supporters, more than 20,000 live

in Virginia. CCAN supporters live, exercise, work, raise children, garden, fish, boat, and

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recreate on a regular basis on or near the route of the Project. CCAN seeks to intervene in

this proceeding because the Project will exacerbate climate change in a region that is

particularly susceptible to the impacts, will lock the region in to future reliance on fossil

fuels while taking resources away from renewable energy and energy efficiency, and will

cause additional environmental and economic harm to our supporters.

The Haw River Assembly is a 501(c)(3) non-profit citizens’ group founded in

1982 to restore and protect the Haw River and Jordan Lake, and to build a watershed

community that shares this vision. Our goals are to promote environmental education,

conservation and pollution prevention; to speak as a voice for the river in the public

arena; and to put into peoples’ hands the tools and the knowledge they need to be

effective guardians of the river.

The Haw River is at the headwaters of the Cape Fear River Basin, and includes

the Jordan Lake reservoir, providing drinking water and recreation to North Carolina.

Tributaries of the Haw River and Jordan Lake flow through Guilford, Rockingham,

Caswell, Alamance, Orange, Chatham, Wake and Durham counties. Almost one million

people are part of this watershed–sedimentation, wastewater, and runoff impair its waters.

The Haw River Assembly is dedicated to the goal of environmental justice and

equality for all people in our watershed. The Haw River Assembly is a stronger

organization and our work to protect water is more successful when our organization

represents the full diversity of people living in our watershed. We believe all people

should have access to enjoyment of the natural world and a voice in decisions that may

affect their environment and/or health. This project poses serious environmental threats

to the Haw River watershed, the people who depend on it for drinking water and

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recreation, and the wildlife who rely on this habitat in an urbanizing region. Our

community should not be put at risk or taken advantage of by corporate greed for this

unnecessary fracked gas pipeline project.

The Sierra Club is a national nonprofit organization of approximately 780,000

members dedicated to exploring, enjoying, and protecting the wild places of the earth; to

practicing and promoting the responsible use of the earth’s ecosystems and resources; to

educating and enlisting humanity to protect and restore the quality of the natural and

human environment; and to using all lawful means to carry out these objectives. Sierra

Club leads the charge to move away from fossil fuels that cause climate disruption and

toward a clean energy economy.

The Virginia Chapter of the Sierra Club is over 19,000 members strong. It has

offices in Northern Virginia, Richmond, Norfolk, and Charlottesville. The North Carolina

Chapter has over 20,000 members and offices located in Raleigh and Wilmington. The

energy choices we make today will impact members for generations to come. Sierra Club

firmly believes that Virginians and North Carolinians want and deserve clean air to

breathe, safe water to drink and good local jobs. But our utilities and many of our leaders

are relying on dirty fuels that put our health at risk, destroy our land and contribute to

climate disruption. Building clean, renewable energy like wind and solar power, and

conserving energy through efficiency programs, will jump start new industries, create

jobs and help keep our families safe from harmful pollution.

The Sierra Club seeks to intervene in this proceeding because the Project impacts

our water resources, fragments our forests, threatens endangered species, disrupts cultural

attachments and communities adjacent to the corridor, impacts our historic resources,

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violates property rights, inflicts economic damage on communities and continues to block

the development of renewable energy sources.

Together, these groups represent thousands of citizens, consumers, and

landowners that would be directly affected by construction and operation of the proposed

pipeline and associated facilities. Although these groups share common goals, each group

has its own independent mission and supporter base and each group joins this motion as

individual movants, requesting independent intervenor status on behalf of their

organizations in the above-captioned proceedings.

The movant’s interests are not adequately represented by any existing party to the

proceeding and their participation would further the public interest. This motion is timely

filed in accordance with FERC’s November 19, 2018 Notice.

II. COMMUNICATIONS AND SERVICE

All communications, pleadings, and orders with respect to this proceeding should

be sent to the following group representatives:

Benjamin A. Luckett

Senior Attorney

Appalachian Mountain Advocates

PO Box 507

Lewisburg, WV 24901

(304) 645-0125

[email protected]

Peter Anderson

Virginia Program Manager

Appalachian Voices

812 East High Street

Charlottesville, VA 22902

(434) 293-6373

[email protected]

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Perrin de Jong

North Carolina Staff Attorney

Center for Biological Diversity

P.O. Box 6414

Asheville, NC 28816

(828) 774-5638

[email protected]

Anne Havemann

General Counsel

Chesapeake Climate Action Network

6930 Carroll Ave, Suite 720

Takoma Park, MD 20912

(240) 396-1984

[email protected]

Emily Sutton

Haw Riverkeeper

Haw River Assembly

PO Box 187

Bynum, NC 27228

(919) 542-5790

[email protected]

Elizabeth F. Benson

Staff Attorney

Sierra Club

2101 Webster Street, Ste. 1300

Oakland, California 94612

(415) 977-5723

[email protected]

III. PROTEST

Pursuant to 18 C.F.R. § 385.211, the above-listed groups file the following protest

in opposition to the issuance of a Certificate of Convenience and Necessity under Section

7 of the Natural Gas Act, 15 U.S.C. § 717f, for the Project. These groups (“Proposed-

Intervenors”) protest the Project because it is not needed, will have significant adverse

impacts on a wide variety of environmental resources, will disrupt the traditional

character of numerous communities and substantially lower property values in the

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vicinity of the project and the supply production areas, and will further commit the nation

to long-term dependence on climate-altering fossil fuels.

This Motion and Protest state the interests and positions of the Proposed-

Intervenors to the extent known at this time. Proposed-Intervenors intend to obtain and

develop additional factual evidence and arguments in this proceeding and reserve the

right to submit those materials to FERC as they are developed.

Under the Natural Gas Act, the Federal Energy Regulatory Commission

(“FERC”) must determine whether the construction of the applicant’s proposed pipeline

“is or will be required by the present or future public convenience and necessity.” 15

U.S.C. § 717f(e). If FERC cannot make that determination, then the “application shall be

denied.” Id. In 1999, FERC issued a Policy Statement setting forth the criteria that it uses

in determining whether to authorize the construction of major new pipeline facilities, i.e.,

whether a proposed pipeline is required by public convenience and necessity. 88 FERC ¶

61227.

The threshold question under the 1999 Policy Statement is “whether the project

can proceed without subsidies from . . . existing customers.” Id. at 61,746. Because the

Project is a new pipeline without existing customers, the threshold question does not

apply to the pending application at issue. Id.1

The second step of the analysis under the 1999 Policy Statement is to address

“whether the applicant has made efforts to eliminate or minimize any adverse effects the

project might have on the existing customers of the pipeline proposing the project,

existing pipelines in the market and their captive customers, or landowners and

1 See also Application at 10–11.

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communities affected by the route of the new pipeline.” Id. at 61,745. Regarding the

latter group, FERC has stated that

[l]andowners whose land would be condemned for the new pipeline right-

of-way, under eminent domain rights conveyed by the Commission’s

certificate, have an interest, as does the community surrounding the right-

of-way. The interest of these groups is to avoid unnecessary construction,

and any adverse effects on their property associated with a permanent

right-of-way.

Id. at 61,748.

If adverse effects on those three interests remain, then FERC must balance those

adverse effects against public benefits of the proposal. Id. at 61,745. “To demonstrate that

its proposal is in the public convenience and necessity, an applicant must show public

benefits that would be achieved by the project that are proportional to the project’s

adverse impacts.” Id. at 61,748. Types of public benefits “could include meeting

unserved demand, eliminating bottlenecks, access to new supplies, lowers costs to

consumers, providing new interconnects that improve the interstate grid, providing

competitive alternatives, increasing electric reliability, or advancing clean air objectives.”

Id. “Vague assertions of public benefits will not be sufficient,” and the stated interests

must outweigh the adverse effects caused by the project for FERC to grant a Certificate.

See id. at 61,748, 61,750; see also Millennium Pipeline Co., 141 FERC ¶ 61,198, 2012

WL 60607320, at *4 (2012). “The more interests adversely affected or the more adverse

impact a project would have on a particular economic interest, the greater the showing of

public benefits from the project required to balance the adverse impact.” Id. at *5.

A crucial component of the assessment of the public benefits of the project is the

determination of whether the project is needed. FERC cannot merely rely on the amount

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of capacity under contract, but must rather look at “all relevant factors reflecting on the

need for the project.” 88 FERC ¶ 61, 744, 61,748. On its face, FERC’s 1999 Certificate

Policy Statement represented a shift in FERC’s evaluation of certificate applications

away from narrow reliance on the existence of precedent agreements towards a more

holistic analysis. Historically, FERC policy required applicants to show market support

for a project through contractual commitments for at least 25 percent of the proposed

pipeline’s capacity. Id. at ¶ 61,743. But in 1999, FERC revised its policy, acknowledging

that the percentage-of-capacity test was inadequate because, in part, “[t]he amount of

capacity under contract . . . is not a sufficient indicator by itself of the need for a project.”

Id. at ¶ 61,744. The Commission further observed that “[u]sing contracts as the primary

indicator of market support for the proposed pipeline project also raises additional

questions when the contracts are held by pipeline affiliates.” Id. In other words, concerns

that capacity contracts in and of themselves are insufficient to demonstrate need are

exacerbated when those contracts exist between affiliated entities.

The 1999 policy statement sought to remedy problems caused by FERC’s long-

standing sole reliance on precedent agreements. To that end, it established a list of means

by which the Commission could assess market benefit, one of the indicators of public

benefit for a proposed project. See id. at ¶ 61,747. Those means included, but were not

limited to “precedent agreements, demand projections, potential cost savings to

consumers, or a comparison of projected demand with the amount of capacity currently

serving the market.” Id. In clarifying its policy, FERC explicitly stated that “as the

natural gas marketplace has changed, the Commission’s traditional factors for

establishing the need for a project, such as contracts and precedent agreements, may no

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longer be a sufficient indicator that a project is in the public convenience and necessity.”

Order Clarifying Statement of Policy, 90 FERC ¶ 61,128, 61,390 (Feb. 9, 2000).

FERC must make these determinations based on the record before it. This means

that, regardless of any applicable presumptions, FERC has a duty to make its own

determination. See Panhandle Producers and Royalty Owners Ass’n v. Econ. Regulatory

Admin., 822 F.2d 1105, 1110–11 (D.C. Cir. 1987). Simply put, “the agency must

examine the relevant data and articulate a satisfactory explanation for its action including

a rational connection between the facts found and the choice made.” Motor Vehicle Mfrs.

Ass’n of the U.S. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983). Mountain

Valley’s application does not support the finding that the ACP is required by the public

convenience and necessity.

A. Mountain Valley Has Not Provided Sufficient Evidence of Market Demand to Support a Finding of Public Convenience and Necessity

Industry analysts are convinced that we have a substantial surplus of pipeline

capacity with existing pipelines, projects under construction, and applications in the

regulatory queue.2 The Energy Information Administration forecasts that residential use

of natural gas will decline by 0.6% per year between now and 2040. Commercial and

industrial uses are expected to increase 0.4% and 0.6% per year, respectively. Industrial

consumption will be especially sensitive to the price of natural gas. Use of gas for

electricity generation is predicted to grow at a rate of 0.5% per year.3 Despite this small

2 See, e.g., June 30, 2017 Comments of Thomas Hadwin in FERC Docket No. CP16-10-

000 on behalf of Friends of the Central Shenandoah (Accession No. 20170630-5306)

(“Hadwin Comments”) at 6–8.

3 Id. at 8.

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predicted increase in demand, and corresponding production levels in the Marcellus and

Utica formation, pipeline takeaway capacity from the region is expanding rapidly:

Industry experts project that given the current drilling activity in the Appalachian Basin

the pipeline capacity in the region will be over 50 percent greater than the production

capacity, at least through 2022.4 The excess of pipeline capacity in the Appalachian Basin

4 Id. at 5 (citing “Drilling Activity: How Much Does the Market Need?, Matthew Hoza,

BTU Analytics, March 14, 2017); see also id. at 11 (“In the mid to long-term,

incremental outbound capacity from Pennsylvania and Ohio is expected to exceed

Marcellus production (i.e., pipeline constraints in Marcellus are a short-term

phenomenon), assuming expected pipeline expansions go in service on time.” (quoting

Quadrennial Energy Review Analysis: Department of Energy, Office of Energy Policy

and Systems Analysis. “Natural Gas Infrastructure Implications of Increased Demand

from the Electric Sector.” February 2015. Appendix B: Natural Gas)).

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provides ready access to markets and will equalize prices between production zones.5 A

study by Synapse Energy Economics found that “given existing pipeline capacity,

existing natural gas storage, the expected reversal of the direction of flow on the existing

Transco pipeline,6 and the expected upgrade of an existing Columbia pipeline, the supply

capacity of the Virginia-Carolinas region’s existing natural gas infrastructure is more

than sufficient to meet expected future peak demand.”7

Even if capacity needs of the Project’s lone customer, Public Service Company of

North Carolina, Inc. (“PSNC Energy”), grow along with projected population increases,

which is not a given, those needs can be met through existing contracted capacity. As the

North Carolina Department of Environmental Quality explained

The region is projected to experience population growth, in an amount that

equates to roughly an 11 % increase in design-day requirements between 2018

and 2023. As shown in Table 1 below, the addition of the throughput delivered by

the Southgate Project would increase the contracted capacity volume by 100%,

which would far exceed the historical deliveries and the growth projected in the

service population.8

5 Id. at 6–7

6 Since the release of that study, FERC approved the Transco reversal as part of the

Atlantic Sunrise Project, Docket No. CP15-138.

7 Synapse Energy Economics, Inc., Are the Atlantic Coast Pipeline and the Mountain

Valley Pipeline Necessary? An examination of the need for additional pipeline capacity

into Virginia and Carolinas, 1-1 (2016) (hereinafter, “Synapse Study”), attached as

Exhibit A. That study was prepared prior to the approval of the Atlantic Coast and

Mountain Valley pipelines, which FERC approved in October 2017 in FERC Dockets

No. CP15-554 and CP16-10, respectively.

8 North Carolina DEQ, November 5, 2018 Comment Regarding Demonstrated Need and

the Public Interest of the Mountain Valley Pipeline- Southgate Extension Project, FERC

Docket No. PF18-4-000 (Accession No. 20181106-5000).

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Mountain Valley has thus not demonstrated that its proposed project is required by the

public convenience and necessity.

B. Mountain Valley’s Affiliate Relationship with PSNC Undermines the Precedent Agreement’ Ability to Demonstrate Market Demand

Mountain Valley’s lone precedent agreement, which it claims supports a finding a

public convenience and necessity, is with PSNC for 300,000 dth/day, or 80 percent of the

Project’s design capacity. After entering the precedent agreement, PSNC purchased a 30

percent ownership interest in the Project. More and more, experts, including former

Commission Chair Norman Bay, agree that pipeline developers use precedent agreements

between the developer and an affiliated regulated utility with captive ratepayers—like the

contracts described above—to justify building pipeline infrastructure in the absence of

actual market demand.9. When the Commission accepts precedent agreements between

9 See J.F. Wilson, Evaluating Market Need for the Atlantic Coast Pipeline 6-12 (2017),

attached as Exhibit B.; Separate Statement of Commissioner Bay, FERC Docket No.

CP15-115 3 (Feb. 3, 2017); S. Isser, Natural Gas Pipeline Certification and Ratemaking

24 (2016), attached as Exhibit C.; Hearing to Examine Oil and Gas Pipeline

Infrastructure and the Economic, Safety, Environmental, Permitting, Construction, and

Maintenance Considerations Associated with that Infrastructure: Hearing Before the S.

Comm. on Energy & Nat. Res., 114th Cong. (June 14, 2016) (statement of N. Jonathan

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affiliated companies, one of which, the shipper, is a regulated utility, for a project of this

scale, it allows the shipper utility to “impose long-term financial obligations on captive

ratepayers.”10 Utility ratepayers bear the risk of the project while the project’s financial

rewards accrue to the shareholders of the utility’s parent company. Or, to put it another

way, the captive utility ratepayers subsidize the new pipeline construction to the benefit of

the parent company’s shareholders. This structure, which shifts the risk from the

shareholders to the ratepayers, subverts the “price signals sent by a rational market”11 and

allows companies to pursue unneeded projects “at the expense of alternative transport

options.”12 Given the manner in which this relationship skews normal market incentives,

FERC must look beyond the affiliate precedent agreement to determine if the project is

truly required by the public convenience and necessity.

IV. CONCLUSION

For the reasons stated above, the above listed groups respectfully request that they

be permitted to intervene as parties in this proceeding and request that FERC set the

Southgate Project application for a full evidentiary hearing to resolve contested issues of

fact regarding the need for the Project and balance of public benefits and adverse impacts

of the Project. Proposed-Intervenors believe that an evidentiary hearing will show that

Mountain Valley cannot demonstrate the need for the Project. Even if FERC finds that

the Project is needed, Proposed-Intervenors believe that a hearing will demonstrate that

Peress, Envt’l Def. Fund at 5) [hereinafter Testimony of N. Jonathan Peress], included as

attached as Exhibit D.; C. Kunkel & T. Sanzillo, Inst. for Energy Econ. & Fin. Analysis,

Risks Associated with Natural Gas Pipeline Expansion in Appalachia 5-6 (2016),

included as attached as Exhibit E. 10 Testimony of N. Jonathan Peress at 5. 11 Id. 12 Isser at 24.

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the adverse effects of the Project substantially outweigh the public benefits of the

proposal and the project is thus not in the public convenience and necessity.

Respectfully submitted on behalf of all parties in this intervention and protest,

Sincerely,

Benjamin A. Luckett

Appalachian Mountain Advocates

PO Box 507

Lewisburg, WV 24901

(304) 645-0125

[email protected]

On behalf of Appalachian Voices, Center for Biological Diversity, Chesapeake Climate

Action Network, Haw River Assembly, and the Sierra Club

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CERTIFICATE OF SERVICE

I hereby certify that I have on December 10, 2018, caused the foregoing

document to be served upon each person designated on the official service list

compiled by the Secretary in this proceeding.

Sincerely,

Benjamin A. Luckett Appalachian Mountain Advocates

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EXHIBIT A

485 Massachusetts Avenue, Suite 2 Cambridge, Massachusetts 02139

617.661.3248 | www.synapse‐energy.com

Are the Atlantic Coast Pipeline and the Mountain Valley Pipeline Necessary?

An examination of the need for additional pipeline capacity into Virginia and Carolinas

Prepared for Southern Environmental Law Center and Appalachian Mountain Advocates

September 12, 2016 AUTHORS

Rachel Wilson Spencer Fields Patrick Knight Ed McGee Wendy Ong Nidhi R. Santen, PhD Thomas Vitolo, PhD Elizabeth A. Stanton, PhD

Synapse Energy Economics, Inc. Proposed Natural Gas Pipelines from West Virginia 1

CONTENTS

EXECUTIVE SUMMARY ............................................................................................... 1 Future demand for natural gas.................................................................................................... 1

Future natural gas supply ........................................................................................................... 2

Result: Natural gas supply exceeds peak demand ....................................................................... 3

Assessing the need for pipeline investment ................................................................................ 4

1. INTRODUCTION ................................................................................................. 5

2. FUTURE DEMAND FOR NATURAL GAS ..................................................................... 6 2.1. Pipeline Developer Assessment of Need ............................................................................ 6

2.2. Estimates of Peak Demand for Natural Gas ...................................................................... 10

3. ANTICIPATED NATURAL GAS SUPPLY ON EXISTING AND UPGRADED INFRASTRUCTURE ....... 11 3.1. Existing Pipelines ............................................................................................................. 13

3.2. Natural Gas Storage ......................................................................................................... 15

3.3. Planned Reversals and Expansions of Existing Pipelines ................................................... 16

4. NATURAL GAS SUPPLY EXCEEDS DEMAND .............................................................. 17

APPENDIX A: NON‐ELECTRIC DEMAND METHODOLOGY AND DATA SOURCES........................ 19

APPENDIX B: ELECTRIC DEMAND METHODOLOGY AND DATA SOURCES ............................... 23

APPENDIX C: WINTER PEAK MODELING ...................................................................... 26


EXECUTIVE SUMMARY

The Southern Environmental Law Center and Appalachian Mountain Advocates retained Synapse Energy Economics, Inc. (Synapse) to determine whether proposed new interstate pipelines that would deliver natural gas from West Virginia to Virginia and the Carolinas are necessary to maintain adequate gas supply to the region. Two new interstate pipelines have been proposed to transport natural gas from the Marcellus Shale into Virginia and the Carolinas:

1) Atlantic Coast Pipeline (proposed by Dominion Pipeline, Duke Energy, Piedmont Natural Gas, and AGL Resources); and

2) Mountain Valley Pipeline (proposed by EQT Midstream Partners, NextEra US Gas Assets, WGL Midstream, and Vega Midstream MVP).

In their proposals, the developers of these projects assert that subscription rates for pipeline capacity demonstrate the need for additional natural gas in the target region, but they fail to compare the region’s existing natural gas supply capacity to its expected future peak demand for natural gas. We undertake that comparison in this report. In the analysis presented here Synapse finds that, in fact, given existing pipeline capacity, existing natural gas storage, the expected reversal of the direction of flow on the existing Transco pipeline, and the expected upgrade of an existing Columbia pipeline, the supply capacity of the Virginia‐Carolinas region’s existing natural gas infrastructure is more than sufficient to meet expected future peak demand. This result raises significant questions about the need for additional investment in new interstate natural gas pipelines in the region and, more generally, the utility of pipeline subscription rates as justification for these projects.

Future demand for natural gas

Synapse developed low and high scenarios of future natural gas use for the study region, defined as Virginia, North Carolina, and South Carolina, to identify the expected range of likely demand for natural gas. Both low and high scenarios comply with the U.S. Environmental Protection Agency’s limits for carbon dioxide emissions under the Clean Air Act. These limits consist of two separate regulations under Section 111(b) (Carbon Pollution Standards), which establishes federal standards for new, modified, and reconstructed power plants, and Section 111(d) (Clean Power Plan), which establishes state‐based standards for existing power plants. While the demand for energy services is the same in each scenario, the low gas use scenario assumes greater energy efficiency savings and a more rapid build out of renewable generating facilities while the high gas use scenario assumes a greater number of retirements of coal‐fired generating units and the use of new and existing natural gas‐fired generators to meet emission goals.

In the high gas use scenario, renewable capacity and savings from energy efficiency in each state are determined by individual Renewable Portfolio Standards and Energy Efficiency Resource Standards. North Carolina is the only state in our study region with a Renewable Portfolio Standard, so its renewable capacity increases to meet its targets. Otherwise, renewable capacity and energy efficiency


savings remain relatively constant in the high gas use scenario throughout the study period. Natural gas is used to meet Clean Power Plan targets, thus representing the outer bound of likely future natural gas demand. For both scenarios, Synapse estimated the highest combined electric and non‐electric natural gas demand in any hour of the year in order to compare this “peak hour” value to the region’s anticipated supply capacity of natural gas. If the region’s natural gas infrastructure can supply sufficient gas during the peak hour of greatest demand, then there should be no obstacle to supplying gas during the rest of the year. Figure ES‐1 shows the peak demand for natural gas in each year during the study period for the low gas use and high gas use scenarios.

Figure ES‐1. Peak demand for natural gas in the low gas use and high gas use scenarios

Future natural gas supply capacity

In Virginia and the Carolinas, peak demand for natural gas is satisfied by the combination of several different types of supply capacity, notably:

Existing pipelines: The existing pipelines belonging to Transco, Cove Point, Columbia Gas Transmission, Dominion Transmission, Southern Natural Gas, South Carolina PL Corporation, East Tennessee Natural Gas, Nora Transmission, and Bluefield Gas have the capacity to supply just over 300 MMcf per hour into the study region.

Reported natural gas storage: Storage is an essential part of every natural gas supply system and plays a critical role in meeting peak demand. Reported liquefied natural gas (LNG) and underground natural gas storage in the region has the capacity to supply 71 MMcf per hour. Not all owners of natural gas infrastructure are required to report storage capacity, so the region’s maximum or actual natural gas storage is not known.

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2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

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Natural gas demand, high gas use

Natural gas demand, low gas use


The “reported” storage value used in this analysis is, therefore, a conservative assumption and, indeed, is lower than the minimum amount of regional storage that existed in 2015 (that is, the difference between pipeline capacity and peak hour demand).

Expected reversals and upgrades of existing pipelines: The reversal of the Transco Mainline pipeline as part of the Atlantic Sunrise project has been proposed before the Federal Energy Regulatory Commission (FERC) and is expected to add the capacity to supply 254 MMcf per hour to the study region in 2017 (changing the export of 127 MMcf to an import of 127 MMcf, for a net change of 254 MMcf). The WB Xpress project, an upgrade to an existing pipeline proposed by Columbia Gas, would add an additional 73 MMcf per hour to the region beginning in 2018.

Result: Natural gas supply capacity exceeds peak demand

Figure ES‐2 compares maximum expected natural gas demand (peak‐hour demand in our high gas scenario) in years 2015 through 2030 to anticipated natural gas supply capacity on existing and upgraded infrastructure, including existing pipelines, reported storage, the 2017 reversal of the Transco Mainline pipeline, and the 2018 WB Xpress project. (Note that reported supply capacity is lower than actual peak hour demand in 2015 and 2016: In all likelihood, the gap in capacity to serve actual peak was supplied by natural gas storage facilities that are not reported in publicly available data sources.)

Figure ES‐2. Maximum peak hour natural gas demand compared to anticipated natural gas supply on existing and upgraded infrastructure

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For Virginia and the Carolinas, the anticipated natural gas supply capacity on existing and upgraded infrastructure is sufficient to meet maximum natural gas demand from 2017 through 2030: Additional interstate natural gas pipelines, like the Atlantic Coast and Mountain Valley projects, are not needed to keep the lights on, homes and businesses heated, and existing and new industrial facilities in production. This assessment of sufficient supply capacity includes only reported storage capacity, ignoring the existence of additional unreported storage capacity demonstrated by recent years’ peak hour demand.

Assessing the need for pipeline investment

Interstate transmission pipeline infrastructure serving Virginia and the Carolinas is part of an interconnected system that includes pipeline and storage capacity both inside and outside of the region. Considering each new pipeline proposal as an isolated project ignores important alternatives that would increase regional natural gas supply capacity and avoid the adverse impacts on communities or the environment that can result from new construction. Alternatives to new pipeline construction include:

Projects that reverse the flow of the Transco pipeline will lead to a significant increase in natural gas capacity in the Virginia and Carolinas region, and make new interstate transmission infrastructure (e.g., the proposed Atlantic Coast Pipeline and the Mountain Valley Pipeline) unnecessary to serve the market in Virginia and the Carolinas. Reversal of the Transco pipeline is one component of the proposed Atlantic Sunrise project.

Investment in additional storage facilities may be a more cost‐effective solution to boosting natural gas supply capacity in those few hours of the year where concerns exist regarding supply constraints.

New or accelerated measures for gas energy efficiency, electricity energy efficiency, demand response (programs that pay large electric consumers to shift demand off of peak hours), and investment in renewable generating resources are critical tools to lower both annual and peak demand for natural gas.

To safeguard public interests, a determination of need for new pipeline infrastructure requires a detailed, integrated analysis of natural gas supply capacity and demand for the region as a whole.


1. INTRODUCTION Two new interstate pipelines have been proposed to transport natural gas from West Virginia into Virginia and the Carolinas: 1) Atlantic Coast Pipeline (proposed by Dominion Pipeline, Duke Energy, Piedmont Natural Gas, and AGL Resources); and 2) Mountain Valley Pipeline (proposed by EQT Midstream Partners, NextEra US Gas Assets, WGL Midstream, and Vega Midstream MVP).1 The developers of both projects assert that these pipelines are necessary to meet regional energy demand now and in the future.

Interstate transmission pipeline infrastructure serving Virginia and the Carolinas is part of an interconnected system that includes natural gas pipeline and storage capacity both inside and outside of the region. For a pipeline developer to establish that a new interstate pipeline is necessary, it would need to demonstrate that existing natural gas capacity in Virginia and the Carolinas region is not sufficient to provide enough gas to meet the demand over the course of a year or—more importantly—in the peak winter hour. For such a demonstration to be defensible, it would be necessary to base estimates of future capacity and demand of natural gas on detailed modeling of both the non‐electric and electric sectors. If there were evidence of a capacity shortage in the model, it would likely present itself through higher natural gas prices and resulting higher electricity prices and/or through modeled results showing curtailment of natural gas‐fired generators.

The developers of the Atlantic Coast and Mountain Valley proposal development projects assert that these pipelines are necessary to meet regional energy demand. Synapse conducted an independent examination of the validity of these statements by analyzing public documents relating to the proposed and existing natural gas infrastructure, and performing a modeling analysis of projected natural gas demand. We conducted our analysis in four steps:

Estimation of winter peak non‐electric demand in our study region

Development of two scenarios of demand for natural gas in the electric sector and low, reference, and high sensitivity assumptions regarding the price of natural gas

Assessment of future natural gas supply in our study region

Analysis of balance between natural gas capacity and demand during the winter peak hour

Section 2 of this report provides an overview of the ways in which pipeline developers have assessed the need for their projects in the filings submitted to the Federal Energy Regulatory Commission. It then describes our own estimates of future peak demand for natural gas.

1 Note that a third pipeline, the Appalachian Connector Pipeline, has also been proposed by the Williams Company but the

necessary application and supporting materials have not yet been filed with the Federal Energy Regulatory Commission.


Section 3 describes existing natural gas capacity infrastructure and anticipated future supply.

Section 4 compares existing and projected natural gas supply with natural gas demand during the winter peak for each modeled year.

Finally, three appendices present detailed modeling assumptions and results:

Appendix A presents the methodology used to estimate non‐electric demand.

Appendix B presents the methodology used to estimate demand from the electric sector.

Appendix C presents the methodology used to develop the estimates of winter peak natural gas use in the ReEDS model.

2. FUTURE DEMAND FOR NATURAL GAS A determination of need for incremental pipeline capacity in the Virginia‐Carolinas region requires a projection of future demand for natural gas from non‐electric (residential, commercial, and industrial) and electric end uses. Residential and commercial use of natural gas is primarily for space and water heating and thus peaks annually in the winter when temperatures are lower. Industrial use often stays consistent from month to month. Regional use of natural gas for electric generation has historically been summer peaking; however, a slight decline in summer gas use in the past year, combined with an increase in winter gas demand, has resulted in similar gas consumption levels in the electric sector for both summer and winter peaks. As a result, when we combine the non‐electric and electric uses for natural gas, we find that the “ultimate system peak,” or hour of maximum natural gas demand, occurs in the winter. In order to ensure adequate supply to consumers, local distribution companies must be able to procure enough natural gas to reliably meet this ultimate system peak.

In their filings with the Federal Energy Regulatory Commission (FERC), pipeline developers must demonstrate that a market need exists for each of the proposed new pipelines, which should include detailed forecasts of expected end‐use demand in the region. However, as described below, the developers’ assessments of need rely primarily on Energy Information Administration (EIA), the statistical and analytical agency within the United States Department of Energy, projections of growth in natural gas used for electric generation.

2.1. Pipeline Developer Assessment of Need The developers of the new natural gas pipelines proposed to run through Virginia and the Carolinas assert that their projects are necessary to meet future energy needs. Under Section 7(c) of the Natural Gas Act of 1938, FERC has jurisdiction over pipeline infrastructure and is authorized to issue certificates of “public convenience and necessity” for “the construction or extension of any facilities...for the


transportation in interstate commerce of natural gas.” FERC’s decision to grant or deny a pipeline certificate is based upon a determination of whether the pipeline project would be in the public interest. The agency accounts for several factors, including a project’s potential impact on pipeline competition, the possibility of overbuilding, subsidization by existing customers, potential environmental impacts, avoidance of the unnecessary use of eminent domain, and other considerations. This determination relies heavily on a demonstrated market need for the proposed new pipeline. FERC requires assessments of the need for new natural gas supply in the study region. Those assessments, which reside in the Resource Report 1 documents filed by the developers, are summarized below.

Atlantic Coast Pipeline

The developers of the Atlantic Coast Pipeline attribute the need for the pipeline largely to their expectation of growth in future electric demand from natural gas generation. The developers cite data from EIA and the U.S. Census Bureau, stating that natural gas demand for all uses in Virginia and North Carolina has grown by 37 and 50 percent, respectively, between 2008 and 2012.2 The pipeline’s developers claim that “demand for natural gas in Virginia and North Carolina is expected to increase in coming decades due to a combination of population growth and displacement of coal‐fired electric power generation.”3 They use the U.S. Census Bureau prediction that between 2000 and 2030, Virginia’s population will grow by 2.7 million residents and North Carolina’s by 4.2 million residents.4 They also state that coal plant retirements and low natural gas prices will cause natural gas to surpass coal as the most common fuel for electric power generation in the region by 2035.5

The Atlantic Coast Pipeline developers commissioned a study from ICF International showing a scenario in which between 2019 and 2038 approximately 9,900 megawatts (MW) of coal and nuclear generating capacity in Virginia and North Carolina will retire, while the region builds 20,200 MW of new natural gas capacity. As a result, ICF predicts that demand for natural gas for electric power generation in the two states will “grow 6.3 percent annually between 2014 and 2035, increasing from 1 Bcf/d (billion cubic feet per day) to 3.7 Bcf/d.”6

In April 2014, Duke Energy and Piedmont issued a request for proposals in North Carolina for incremental pipeline transportation service, citing their “existing and future natural gas generation requirements, core load growth, and system reliability and diversity goals.”7 Virginia Power Services Energy Corp, Inc. issued a similar request to serve Virginia. These companies contracted for

2 Natural Resource Group. 2015. Draft Resource Report 1: General Project Description. Prepared for Atlantic Coast Pipeline, LLC

Docket No. PF15‐6‐000 and Dominion Transmission, Inc. Docket No PF15‐5‐000. Available online at: https://www.dom.com/library/domcom/pdfs/gas‐transmission/atlantic‐coast‐pipeline/acp‐shp‐rr1‐1.pdf.

3 Ibid. 4 Ibid. 5 Ibid. 6 Ibid, page 1‐5. 7 Ibid, page 1‐5.


transportation service on the Atlantic Coast Pipeline, along with other companies in the region. According to the pipeline’s developers, “over 90 percent of the new pipeline system’s capacity has been contracted for in binding precedent agreements with major utilities and local distribution companies…(and) (t)he ACP [Atlantic Coast Pipeline] is not designed to export natural gas overseas; this is not a component of the purpose and need of the ACP.”8

Mountain Valley Pipeline

The assessment of need from the developers of the Mountain Valley Pipeline has fewer details, though they also base their needs assessment on their expectation of growth in electric power generation from natural gas. Developers state that the EIA predicts total U.S. natural gas consumption will increase from 25.6 trillion cubic feet in 2012 to 31.6 trillion cubic feet in 2040, with much of this increase in demand coming from the electric sector.9 Developers also state that “the increased demand for natural gas is expected to be especially high in the southeastern United States, as coal‐fired generation plants convert to or are replaced by natural gas fired generation plants. The infrastructure design of the Project is expected to benefit these regions by connecting the production supply to the market demand.”10 Finally, according to the developers, “MVP [Mountain Valley Pipeline] may also support additional uses of natural gas in south central West Virginia and southwest Virginia by providing an open access pipeline that can facilitate interconnects and subsequent economic development associated with having access to affordable gas supplies, as these areas currently have limited interstate pipeline capacity.”11The Mountain Valley Pipeline reports that it has secured 20‐year commitments for firm transportation capacity for its full capacity, though the amount of gas that will be contracted for has not been reported at this time.12

Summary

The assessment of need from the developers of these proposed pipelines rely entirely on the expectation that there will be significant growth in regional natural gas use for electric power generation over the next 20 years. Developers expect that the Atlantic Coast Pipeline and Mountain Valley Pipeline will primarily (1) serve new natural gas‐fired electric generating units constructed to replace retiring coal units or (2) meet growing electric demand in Virginia and North Carolina. Both pipeline developers rely on projections of electric demand and infrastructure additions from the EIA; however, the EIA has

8 Ibid, page 1‐7. 9 Mountain Valley Pipeline Project. 2015. Resource Report 1 – General Project Description. Prepared for Docket No. PF‐15‐3.

Available online at: http://www.mountainvalleypipeline.info/current‐news. 10 Ibid. 11 Ibid. 12 Business Wire. 2016. Mountain Valley Pipeline Secures New Shipper Commitment with Con Edison. Available online at: http://www.businesswire.com/news/home/20160122005701/en/Mountain‐Valley‐Pipeline‐Secures‐Shipper‐Commitment‐Con


revised its forecasts of electricity consumption steadily downward over the last 15 years, as shown in Figure 1.

Figure 1. Historic EIA forecasts of electricity consumption, as published in the Annual Energy Outlook (AEO)

Pipeline developers also rely on subscription rates as a demonstration of need for new pipeline capacity. However, many of the customers that have contracted for capacity on these proposed pipelines are affiliates or subsidiaries of the pipeline owners, and are regulated utilities that pass pipeline costs to consumers through rates.

Of the two proposed pipeline developers that have filed an assessment of need, only the Atlantic Coast Pipeline developer did a modeling study to quantify the projected increase in natural gas demand. Neither developer assessed current and projected pipeline and storage capacity in the region to determine whether it is adequate to meet a projected increase in natural gas demand.

Pipeline Economics

Insufficient capacity to meet expected future natural gas demand is not the only reason that may explain proposals to develop new natural gas pipelines. Reasons for private investors to advance proposals for new natural gas supply infrastructure also include:

A secure return on investment: Guaranteed—or otherwise very secure—avenues for returns on investments in natural gas pipelines are possible if utilities receive legislative, utility commission, or FERC approval to recover pipeline expenditures from gas or electric customers. These returns are, at time, higher than those for other investment opportunities.

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Market benefits from lower or higher natural gas prices: Large corporations with diverse holdings may take actions that depress or inflate the price of natural gas. These actions may have complex benefits in other related markets such as providing a stimulus for additional fuel switching to natural gas.

Commitment to the future of natural gas: For corporations with both deep and wide‐spread investments in the future of natural gas, actions to further entrench public energy infrastructure in this fuel may have long‐run benefits unrelated to meeting current or near‐future demand.

Interplay between market competitors: Companies that have the development of natural gas pipelines as a core business area may propose pipelines early—before their competitors—as part of a long‐run strategy to protect their market share.

Overseas exports: The expected rapid expansion of U.S. exports of liquefied natural gas (LNG) over the next five to ten years will require sufficient infrastructure to deliver natural gas to existing and proposed LNG terminals. Pipeline developers that are confident that demand for U.S. LNG exports is on the rise have an additional motivation to expand their ownership interests in natural gas supply infrastructure.

2.2. Estimates of Peak Demand for Natural Gas Synapse projected peak demand for natural gas in Virginia and the Carolinas from 2015 to 2030. This projection had two components: non‐electric natural gas demand and demand for natural gas from the electric sector. Forecasts of non‐electric demand for natural gas reflect demand projections from natural gas suppliers in the Virginia‐Carolinas region under a single scenario, commonly referred to as the “design‐day” forecast. However, demand for natural gas from the electric sector is highly dependent upon the compliance pathway that each state decides to pursue to meet its individual reduction targets for emissions of carbon dioxide (CO2) as established under the Clean Air Act’s regulation of new and existing power plants.

We estimated peak natural gas demand under two scenarios: (1) a low gas use scenario that assumes compliance with the Clean Air Act through greater energy efficiency savings and a more rapid build out of renewable generating facilities; and (2) a high gas use scenario that assumes increased use of natural gas for electric power generation (thus representing the maximum expected gas use in the region). As described in more detail in Appendix A, we relied primarily on filings from natural gas distribution companies with the public utility commissions in their respective states as the basis for our forecast of non‐electric natural gas use. For the electric sector, we used the National Renewable Laboratory’s Regional Energy Deployment System (ReEDS model) to simulate electric system dispatch in the Eastern Interconnection and provide the forecasted volume of peak natural gas use under our high gas use and low gas use scenarios.

We then combined the forecast of peak non‐electric demand with the forecasts of electric sector natural gas demand under both the high gas use and low gas use scenarios, as shown in Figure 2.


Figure 2. Combined peak demand for natural gas (non‐electric and electric) in the low gas use and high gas use scenarios

As shown in Figure 2, total demand for natural gas is higher in the high gas use scenario when companies rely on gas‐fired generators to meet Clean Air Act goals. Demand in the peak hour reaches 597 MMcf in 2030 in this scenario, which reflects the maximum possible gas use in the region during the study period, compared to a peak‐hour demand of 515 MMcf in the scenario that relies upon increased additions of renewable energy and energy efficiency in order to meet emissions reduction targets for CO2.

3. ANTICIPATED NATURAL GAS SUPPLY ON EXISTING AND UPGRADED INFRASTRUCTURE

A determination of need for additional incremental pipeline capacity in the Virginia‐Carolinas region also requires an inventory of existing natural gas infrastructure and planned upgrades and modifications to that infrastructure and an assessment of whether or not that supply flow is adequate to meet projected demand. The forms of natural gas capacity infrastructure considered in this analysis include existing pipeline capacity, existing storage, and future reversals and expansions of existing pipelines that would bring additional natural gas into the Virginia‐Carolinas region. Inter‐ and intrastate natural gas pipelines transport gas from producing areas to both local distribution companies and directly to large consumers

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like electric power plants. These natural gas supplies typically help regions meet baseload (that is, average or everyday) natural gas demand, while storage resources contribute to meeting peak demand. Natural gas can be stored underground in aquifers, salt caverns, and depleted oil and gas fields, as well as aboveground in tanks that allow storage in liquid form.

Figure 3 gives an example graphical representation of the relationship between natural gas demand and natural gas supply infrastructure. The graph shows the forecasted winter demand for natural gas in 2015 and the supply available in the region from Piedmont Natural Gas, a distributor of natural gas in North and South Carolina, to meet that demand. The black line represents natural gas demand, and the colored rectangles represent the various types of capacity infrastructure used to meet demand on a given day. The graph shows pipeline capacity at the bottom of the stack, with the Transco, Columbia, Sunbelt, and East Tennessee pipelines providing natural gas in each of the 151 days shown on the graph. Base storage capacity is shown in the middle of the graph, and is represented by the Hardy storage facility as well as the storage services available on the Dominion, Columbia and Transco systems. Finally, the top tier of the graph shows available LNG storage, which is used to meet demand on a small number of peak winter days, and includes the Pine Needle, PNG LNG, and Transco LNG facilities. Note that in 2015 the Piedmont Natural Gas territory—as is common throughout the Virginia‐Carolinas region—requires natural gas storage facilities in order to adequately supply natural gas on approximately 50 percent of winter days.


Figure 3. Piedmont Natural Gas 2015 design winter supply and demand – total Carolinas

Source: Piedmont Natural Gas. Testimony and Exhibits of Michelle R. Mendoza before the Public Service Commission of South Carolina. Docket No. 2015‐4‐G. June 3, 2015.

Synapse reviewed available information on existing pipelines in Virginia and the Carolinas in order to determine the capacity of the region’s current natural gas infrastructure. Existing natural gas capacity comprises:

existing pipeline capacity in the three‐state region of Virginia, North Carolina, and South Carolina; and

existing storage capacity within the region.

The following sections describe the region’s existing and projected natural gas infrastructure in more detail.

3.1. Existing Pipelines To estimate existing capacity in this analysis, we considered “historical in‐flow,” which limits the capacity to the pipeline inflow that existed in 2014, less any contracts out of the region. It is important to note that not all natural gas that originates in or passes through the region is meant for local use. We exclude


gas under contract for capacity outside of the region from our estimation of the volume of gas available to contribute to in‐region capacity. Figure 4 shows the existing pipelines currently in place in the region, along with a table detailing the current in‐flow and out‐flow capacity of these pipelines according to EIA data from 2014.

Figure 4. Currently existing natural gas supply capacity into and out of the Virginia‐Carolinas three‐state region

Source: Synapse analysis based on data from EIA. U.S. state‐to‐state capacity. December 2014. Available at: http://www.eia.gov/naturalgas/pipelines/EIA‐StatetoStateCapacity.xls. Note: Locations of pipelines are approximate and are not meant to portray the exact pipeline locations.

Note that the Williams Company placed the Transco Virginia Southside Expansion project into service in September 2015.13 The 2014 EIA data shown in Figure 4 does not include that project, and Synapse added it to our estimate of the existing total pipeline capacity.

Figure 4 above shows the net capacity from existing pipelines in MMcf per day. In order to calculate the capacity from existing pipelines in the peak hour, we employ the industry standard assumption that 5.6

13 Williams Company. 2015. “Williams’ Transco Completes Virginia Southside Expansion.” September 1. Available online at:

http://investor.williams.com/press‐release/williams/williams‐transco‐completes‐virginia‐southside‐expansion


percent of daily gas demand occurs in the peak hour.14 Estimated natural gas capacity available from existing pipelines during the peak hour is approximately 309 MMcf for the duration of the analysis period.

3.2. Natural Gas Storage While natural gas pipeline capacity is used to meet baseload (average day‐to‐day) demand for natural gas, gas storage facilities play an essential role in meeting peak demand. As a standard, continual practice, natural gas is injected into these storage facilities during periods of low gas demand and withdrawn during peak periods. Peak send‐out capacity in the Virginia‐Carolinas region must provide sufficient volumes of natural gas to meet demand on even the coldest winter day. To do so requires a combination of pipeline and storage capacity resources.

Natural gas can be stored in several ways:

Underground reservoirs are the primary form of natural gas storage, and consist of depleted oil and gas reservoirs, aquifers, and salt caverns. Suppliers can draw from these underground facilities to meet base demand or demand during peak periods.

Aboveground facilities, such as LNG storage tanks, serve primarily during periods of peak demand and offer several advantages over underground facilities. LNG storage occupies less space than underground facilities, as they store natural gas in liquid form. For this reason, they tend to be in closer proximity to end‐use markets and can often provide higher levels of deliverability on short notice.

“Line packing,” in which natural gas is stored temporarily in existing pipelines by packing additional gas volumes into pipelines, provides additional natural gas during peak demand periods.

Owners and operators of natural gas storage facilities tend to be: 1) interstate and intrastate pipeline companies, which use storage to meet the demand of end‐use customers; 2) local gas distribution companies, which use gas from storage to serve customers directly; and 3) independent storage service providers. Government authorities do not require all owners and operators of natural gas infrastructure to report their storage capacity, so we do not know the region’s maximum or actual natural gas storage. We collected the Pipeline and Hazardous Materials Safety Administration’s partial data on LNG facilities in the Virginia‐Carolinas region, as well as EIA’s data on the region’s underground storage facilities. Together, these values make up the “reported” storage value used in this analysis. The hourly capacity contribution of reported storage is estimated to be 71 MMcf per hour and is shown in Table 1, below.

14 Levitan & Associates, Inc. 2015. Gas‐Electric System Interface Study Target 2 Report: Evaluate the Capability of the Natural

Gas Systems to Satisfy the Needs of the Electric Systems. Prepared for the Eastern Interconnection Planning Collaborative. p.82. Available online at: http://nebula.wsimg.com/c1a27fe57283e35da35df90f71a63f7a?AccessKeyId=E28DFA42F06A3AC21303&disposition=0&alloworigin=1


Table 1. Storage capacity of LNG and underground facilities with deliverability to the Virginia‐Carolinas region

Sources: (a) Pipeline and Hazardous Materials Safety Administration. Distribution, Transmission & Gathering, LNG, and Liquid Annual Data. Liquefied Natural Gas (LNG) Annual Data – 2010 to present. Available at http://phmsa.dot.gov/pipeline/library/data-stats/distribution-transmission-and-gathering-lng-and-liquid-annual-data; (b) US EIA. Natural Gas Annual Respondent Query System (EIA-191 Data through 2015). Available at http://www.eia.gov/cfapps/ngqs/ngqs.cfm?f_report=RP7

The estimate of 71 MMcf per hour from storage is a conservative assumption. The Hardy storage facility in West Virginia is included in this estimate because publicly available documentation demonstrates that distribution companies in the Virginia‐Carolinas region contract for storage with this facility. In addition, EIA data show the existence of an additional 149 MMcf/hour of active natural gas storage in West Virginia that we did not include in our estimate due to lack of evidence that this storage was contractually available to local distributors in our study area.

3.3. Planned Reversals and Expansions of Existing Pipelines The major interstate pipelines continue to announce new expansion projects aimed at delivering gas from the Marcellus area to reach anticipated markets. Of the many proposals submitted to FERC that would affect markets across the United States, several propose large‐scale expansion projects intended to deliver natural gas to the Virginia‐Carolinas region.

The largest of these is Transco’s Atlantic Sunrise project, which would reverse the flow of the Transco pipeline and allow the company to provide 1,675 MMcf per day of incremental firm transportation capacity for natural gas from northern Pennsylvania through our study region, terminating in Alabama. The expected in‐service date for the project is July 1, 2017.15 Transco in‐flows and out‐flows were

15 Transcontinental Gas Pipe Line Company, LLC. 2015. Resource Report No. 1: General Project Description. Prepared for Atlantic

Sunrise Project Docket No. CP15‐138. Available online at: http://elibrary.ferc.gov/idmws/file_list.asp?accession_num=20150331‐5153

Company Name Facility Type Facility Name StateTotal Daily Capacity

(MMcf)Hourly capacity

(MMcf)Columbia Gas of Virginia Inc LNG Lynchburg LNG VA 6 0.3

Columbia Gas Transmission, LLC LNG Chesapeake LNG VA 120 5.0

Greenville Utilities Commission LNG LNG Plant NC 24 1.0

Piedmont Natural Gas Co Inc LNG Bentonville LNG NC 180 7.5

Piedmont Natural Gas Co Inc LNG Huntersville LNG NC 200 8.3

Public Service Co of North Carolina LNG PSNC Energy LNG NC 110 4.6

Roanoke Gas Co LNG LNG Facility VA 30 1.3

South Carolina Electric & Gas Co LNG Salley LNG SC 90 3.8

South Carolina Electric & Gas Co LNG Bushy Park LNG SC 60 2.5

Pine Needle Operating Company, LLC LNG Pine Needle LNG NC 400 16.7

Columbia Gas/Piedmont Natural Gas Underground Hardy WV 170.9 7.1

Spectra Energy Underground Early Grove VA 20 0.8

Spectra Energy Underground Saltville VA 300 12.5

1,710.9 71.3Total


included in our calculations of existing pipeline capacity. We assume that with the reversal of the Transco pipeline, the out‐flows would be eliminated, and there would be a corresponding increase of in‐flows, resulting in a net gain of 254 MMcf per hour of peak capacity from the Atlantic Sunrise project.

NiSource’s Columbia Gas Transmission Company (TCO) has announced a number of new pipeline expansion projects including its WB Xpress project, designed to send additional shale gas supplies (about 1.3 Bcf per day) east from the Marcellus to West Virginia, Virginia, and the Cove Point LNG facility in Maryland. The WB XPress project would replace about 26 miles of existing TCO pipeline with a new line of the same diameter. Increased flows would result from the use of higher pressures that the new line would carry. The project, which the company anticipates being in‐service in 2018, would add approximately 73 MMcf per hour of peak capacity.

4. NATURAL GAS SUPPLY EXCEEDS DEMAND Figure 5 compares our modeled maximum expected natural gas demand (peak‐hour demand in our scenario of high gas use) in years 2015 through 2030 to future natural gas infrastructure, including existing pipeline capacity, reported storage, the expected 2017 reversal of the Transco Mainline pipeline, and the expected 2018 WB Xpress project. (Note that reported capacity is lower than actual peak hour demand in 2015 and 2016. In all likelihood, the gap in capacity to serve actual peak was supplied by natural gas storage facilities that are not reported in publicly available data sources and/or by some portion of the 149 MMcf/hour of active storage located in West Virginia.)

The region’s anticipated natural gas supply on existing and upgraded infrastructure is sufficient to meet maximum natural gas demand from 2017 through 2030. Additional interstate natural gas pipelines, like the Atlantic Coast Pipeline and the Mountain Valley Pipeline, are not needed to keep the lights on, homes and businesses heated, and industrial facilities in production. This assessment of sufficient capacity includes only reported storage capacity, ignoring the existence of additional unreported storage capacity demonstrated by recent years’ peak hour demand.


Figure 5. Peak hour natural gas demand under scenarios of low and high natural gas use compared to anticipated natural gas supply on existing and upgraded infrastructure

Figure 5 shows an excess of natural gas supply under a scenario of maximum natural gas demand. The policy pathway chosen by states for compliance with Clean Power Plan emissions reduction targets has a significant impact on the magnitude of this excess supply capacity, as shown in Figure 7. Under the high natural gas use scenario, where Clean Power Plan compliance is achieved primarily through the addition of new natural gas combined‐cycle power plants, peak demand for natural gas climbs steadily throughout the study period and results in excess natural gas supply of approximately 100 MMcf per hour in 2030. In contrast, the low gas use scenario, which minimizes the addition of new NGCC generators and instead relies on new installations of renewable energy capacity and savings through efficiency measures, results in surplus supply of almost 200 MMcf per hour.

Projected future natural gas demand depends greatly on the policies pursued by each of the states in this analysis. While non‐electric natural gas demand remains fairly constant during our analysis period, natural gas demand from the electric sector rises significantly over time in a scenario of high natural gas use, where the states pursue Clean Power Plan compliance through the use of new natural gas generating capacity. If states choose to pursue additional energy efficiency and renewable energy capacity under a scenario of low gas use, combined natural gas demand rises much more slowly over time and results in an even greater capacity surplus in 2030.

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APPENDIX A: NON‐ELECTRIC DEMAND METHODOLOGY AND DATA SOURCES

As an input to our modeling, we calculated projected demand for natural gas in Virginia and the Carolinas from 2015 to 2030.16 This projection had two components: non‐electric natural gas demand and demand for natural gas from the electric sector. As described below, we relied primarily on EIA data for the former and we used the Regional Energy Deployment System (ReEDS model) to calculate the latter. We projected natural gas demand for two different time periods, first calculating annual natural gas demand, and next making a projection of winter peak demand—the amount of natural gas consumed in both sectors at the hour of maximum demand. This section describes the methodology and data sources used to forecast non‐electric natural gas demand, while Appendix B provides further detail on the methodology and data sources used to estimate natural gas demand from the electric sector.

Synapse based its forecast of non‐electric natural gas demand for the states included in the analysis—North Carolina, South Carolina, and Virginia—on data from EIA’s 2015 Annual Energy Outlook (AEO). EIA publishes data on forecasted natural gas demand in the residential, commercial, industrial, and transportation sectors for the South Atlantic Region of the United States through 2040. We took the historical natural gas consumption rates by state and by sector and applied them to the forecasted regional natural gas demand in order to arrive at a forecast of annual non‐electric demand for each of the three states in our analysis. These results are shown in Figure A‐1.

16 U.S. Energy Information Administration. 2015. Annual Energy Outlook.


Figure A‐1. Projected annual non‐electric natural gas demand

Source: EIA 2015 Annual Energy Outlook.

Second, projected non‐electric winter peak demand was calculated using filings with state public utilities commissions from the 13 gas distribution companies located within the three states in this analysis. We reviewed filings from each local distribution company for the most recent year to determine the companies’ “design day” natural gas requirements—the volume of gas needed to meet customer demand on the coldest winter day—and then summed the results across the distribution companies to arrive at design day totals for each of the three states. Companies typically presented results for the next one to five years in the future. Based on these results, we calculated compound annual growth rates for each company and applied them to future years to generate a forecast through 2030. In order to arrive at peak hour requirements from the design day, we assumed that the volume used in the peak hour of the design day represents 5.6 percent of the total design day volume.17 Those projections of non‐electric wint

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